This invention relates to the area of oil and natural gas exploration and, more particularly, to a method for identifying regions of rock formations having significant water saturations from which hydrocarbons may be produced without significant attendant water production.
Subsurface reservoirs of natural gas and petroleum, hereinafter referred to generically as "hydrocarbons" are typically found trapped in permeable geological strata beneath a layer of impermeable strata material. A hydrocarbon will "float" upon any ground water present although typically, a transition zone will exist between the two fluids due to the water being raised by capillary action of the permeable strata material. In some regions, impermeable layers may be relatively closely stacked atop one another trapping thin zones of what may be essentially hydrocarbons, essentially water or mixed hydrocarbons and water. A well bore dropped through the formation and various layers may produce water if tapped (completed) in a transition region or mixed hydrocarbon and water zone. The determination of water saturation aids in the selection of completion intervals and in estimating the amount of hydrocarbons in place. Errors in water saturation determinations can result in (a) erroneous estimates of hydrocarbons in place, (b) the tapping of intervals with excessive amount of attendant water production, originally believed they would be predominantly productive of hydrocarbons, resulting in increased costs of production, and (c) the bypassing of intervals originally believed they would produce an excessive amount of attendant water.
Water saturation present at various levels of a formation is typically determined from interpretation of conventional electrical (i.e., resistivity) logs taken through a borehole dropped through the formation. Water saturation of the available pore space of the formation is determined from the resistivity log measurements using the Archie equation: EQU S.sub.w.sup.n =aR.sub.w /.phi..sup.m R.sub.t, (1)
where "S.sub.w " is the fractional water saturation (i.e. free and bound water of the formation expressed as a percent of the available pore space of the formation), "a" is a formation resistivity coefficient, "R.sub.w " is the formation water resistivity, ".phi." is the formation porosity, "R.sub.t " is the formation resistivity indicated by the resistivity log, "n" is the saturation exponent and "m" is the porosity or cementation exponent. The Archie equation may be expressed in other ways and there are numerous methods in the art for determining, measuring or otherwise obtaining the various components needed to predict fractional water saturation S.sub.w from the log-indicated resistivity, R.sub.t, using the equation in any of its forms.
The desired oil saturation estimate S.sub.o can be determined in accordance with the following expression after solving eq. (1) for water saturation S.sub.w : EQU S.sub.o =1-S.sub.w ( 2)
In gas reservoirs, the gas saturation, Sg, is: EQU Sg=1-Sw (3)
While such a resistivity log interpretation is used to determine water saturation, it can be adversely affected by various factors such as lithologic changes and mineral composition, hole size, bed thickness, type of mud and filtrate invasion. Also, measurement of the saturation exponent "n" for use in solving the Archie equation for water saturation may be unreliable.
Other available methods for water saturation determination include well tests and core analysis. Drill stem tests provide data on the type and amounts of fluids produced from selected intervals. They do not provide fluid saturation data and cannot be used to define fluid-water contacts. The produced water could be due to water coning from a lower interval, or water intrusion from an upper interval through leaky casing or faulty cement job. Repeat formation testers do not provide fluid saturation data, but can furnish reliable fluid-water contact estimates under favorable conditions. Tool problems such as differential sticking, seal failure and probe plugging, or supercharging and threshold phenomena can limit their applicability. Laboratory analysis on core samples cut with an oil base mud can provide a qualitative indication of water saturation above the transition zone. Water loss due to evaporation during core handling operations can be excessive, especially if the reservoir temperature is relatively high. Such analysis fails to identify the oil-water contact in oil reservoirs because the filtrate can indicate oil saturation below the free water level. It is also not applicable in gas wells, especially if the bottom hole temperature is higher than the boiling point of water. Excessive core water evaporation at the surface can mask the actual increase in its saturation with depth, thus rendering the technique useless. Laboratory capillary pressure tests provide data relating the capillary pressure to water saturation above the free water level. In applying the data to an actual reservoir, the free water level must be determined by other means. The capillary pressure across an interface of a pair of fluids, such as oil and water, is defined as: ##EQU1## where "Po" is the oil phase pressure, "Pw" is the water phase pressure, ".delta.ow" is the interfacial tension between the oil and water, ".phi." is the contact angle of the denser phase with the solid surface, and "r" is the radius of the capillary opening. The balance between capillary and gravitational forces yields: EQU Pc=.DELTA..rho.gh (5)
where ".DELTA..rho." is the density difference between water and oil, "g" is the acceleration due to gravity, and "h" is the height above the oil-water contact. Capillary pressure data obtained at laboratory conditions using laboratory fluids must be converted to reservoir conditions using the following relationship: ##EQU2## where the subscripts "R" and "L" denote reservoir and laboratory conditions, respectively. The ratio of interfacial tensions in Equation (6) is difficult to measure while the contact angles are usually obtained using polished crystals of silica or limestone. Consequently, the data conversion using Equation (6) may not be adequate. In addition, core sample wettability may be different from in-situ reservoir wettability, thus resulting in non-representative data.
It is therefore a specific object of the present invention to provide a new method for determining subterranean formation fluid characteristics which overcomes the problems and limitations of the foregoing described prior art methods.